The present invention relates to systems and methods useful in subterranean treatment operations. More particularly, the present invention relates to systems and methods for treating subterranean formations using low-molecular-weight fluids.
Hydrocarbon-bearing subterranean formations penetrated by well bores often may be treated to increase their permeability or conductivity, and thereby facilitate greater hydrocarbon production therefrom. One such production stimulation treatment, known as “fracturing,” involves injecting a treatment fluid (e.g., a “fracturing fluid”) into a portion of a subterranean formation at a rate and pressure sufficient to create or enhance at least one fracture therein. Fracturing fluids commonly comprise a proppant material (e.g., sand, or other particulate material) suspended within the fracturing fluid, which may be deposited into the created fractures. The proppant material functions, inter alia, to prevent the formed fractures from re-closing upon termination of the fracturing operation. Upon placement of the proppant in the formed fractures, conductive channels may remain within the zone or formation, through which channels produced fluids readily may flow to the well bore upon completion of the fracturing operation.
Because most fracturing fluids should suspend proppant material, the viscosity of fracturing fluids often has been increased through inclusion of a viscosifier. After a viscosified fracturing fluid has been pumped into the formation to create or enhance at least one fracture therein, the fracturing fluid generally may be “broken” (e.g., caused to revert into a low viscosity fluid), to facilitate its removal from the formation. The breaking of viscosified fracturing fluids commonly has been accomplished by including a breaker within the fracturing fluid.
Conventional fracturing fluids usually are water-based liquids containing a viscosifier that comprises a polysaccharide (e.g., guar gum). Guar, and derivatized guar polymers such as hydroxypropylguar, are water-soluble polymers that may be used to create viscosity in an aqueous fracturing fluid, and that readily may be crosslinked to further increase the viscosity of the fracturing fluid. While the use of gelled and crosslinked polysaccharide-containing fracturing fluids has been successful, such fracturing fluids often have not been thermally stable at temperatures above about 200° F. That is, their viscosities may decrease over time at high temperatures. To offset the decreased viscosity, the concentration of the viscosifier often may be increased, which may result in, inter alia, increased costs and increased friction pressure in the tubing through which the fracturing fluid is injected into a subterranean formation. This may increase the difficulty of pumping the fracturing fluids. Thermal stabilizers, such as sodium thiosulfate, often have been included in fracturing fluids, e.g., to scavenge oxygen and thereby increase the stabilities of fracturing fluids at high temperatures. However, the use of thermal stabilizers also may increase the cost of the fracturing fluids.
Certain types of subterranean formations, such as certain types of shales and coals, may respond unfavorably to fracturing with conventional fracturing fluids. For example, in addition to opening a main, dominant fracture, the fracturing fluid may further invade numerous natural fractures (or “butts” and “cleats,” where the formation comprises coal) that may intersect the main fracture, which may cause conventional viscosifiers within the fracturing fluid to invade intersecting natural fractures. When the natural fractures re-close at the conclusion of the fracturing operation, the conventional viscosifiers may become trapped therein, and may obstruct the flow of hydrocarbons from the natural fractures to the main fracture. Further, even in circumstances where the viscosifier does not become trapped within the natural fractures, a thin coating of gel nevertheless may remain on the surface of the natural fractures after the conclusion of the fracturing operation. This may be problematic, inter alia, where the production of hydrocarbons from the subterranean formation involves processes such as desorption of the hydrocarbon from the surface of the formation. Previous attempts to solve these problems have involved the use of less viscous fracturing fluids, such as non-gelled water. However, this may be problematic, inter alia, because such fluids may prematurely dilate natural fractures perpendicular to the main fracture—a problem often referred to as “near well bore fracture complexity,” or “near well bore tortuosity.” This may be problematic because the creation of multiple fractures, as opposed to one or a few dominant fractures, may result in reduced penetration into the formation, e.g., for a given injection rate, many short fractures may be created rather than one, or a few, lengthy fracture(s). This may be problematic because in low permeability formations, the driving factor to increase productivity often is the fracture length. Furthermore, the use of less viscous fracturing fluids also may require excessive fluid volumes, and/or excessive injection pressure. Excessive injection pressure may frustrate attempts to place proppant into the fracture, thereby reducing the likelihood that the fracturing operation will increase hydrocarbon production.
It often is desirable to selectively treat hydrocarbon formations to extract hydrocarbons therefrom while isolating the formation from other intervals in a well bore. Such selective treatment operations may include perforating well casing that may be installed in the well bore, and introducing a fracturing fluid through tubing into a tool assembly in the casing, and to a ported sub, or the like, connected in the tool assembly. The fracturing fluid generally discharges from the ported sub at a relatively high pressure, and passes through the perforations in the well casing and into the formation to create or enhance at least one fracture therein. Often, the formation may be isolated by setting packers above, and below, the ported sub to isolate the zone during the fracturing operation.
However, these types of techniques may be problematic. For example, the use of a packer above the ported sub may create a high pressure differential between the formation and the area of the well above the packer, which may cause the packer to unseat during operation, possibly resulting in an unsuccessful fracture treatment, tool damage, and loss of well control.
Also, the introduction of fracturing fluid through the tubing and tool assembly may create additional problems, not the least of which may be the fluid friction created by the flow of the fracturing fluid, which may lead to mechanical failure of both the tubing and tool assembly.